During the last decade, smart waterflooding has been developed as a promising IOR technology for carbonate and sandstone reservoirs. In general, decreasing the injection brine salinity may increase the oil recovery. Extensive research has been conducted to study the causative mechanisms for the additional oil recovery, yet no consensus among researchers has arisen. The main conclusion of previous studies suggest that is the rock wettability alteration towards more water conditions that helps to improve oil recovery. In contrast, we propose that fluid-fluid iteractions reflecting oil/brine visco-elastic interfacial buildup may minimize snap-off and favor coalescence of the oil during waterflooding, and as result, oil recovery is increased. The formation of the oil/brine interface depends on salinity and type of ions contained in solution, as well as asphaltenes and organic acids in oil. The presence of asphaltenes and sulfate ions in the system increases the interfacial visco-elasticity and organic acids weaken the interface. Our experiments suggest that low-salinity water injection is not always necessary to increase oil recovery, if an adequate high-salinity brine is designed to maximize fluid-fluid effects. On the other hand, the SP enhanced oil recovery process is tremendously affected by the carrying fluid, especially in the presence of Ca and Mg, aggravating more at high temperatures. These conditions can be a limitation for many surfactant and polymers in the market. We designed an SP formulation for an offshore, carbonate, heavy oil reservoir, where seawater was used as the carrying fluid. The forced imbibition results turned out promising in terms of oil recovery, reaching almost 90%. The protocol using Nuclear Magnetic Resonance (NMR) spectroscopy, developed during this dissertation, was used to estimate Critical Micelle Concentration (CMC) and individual component's concentration for coreflooding effluents and static adsorption estimation.